Executive Summary

The release of EPA’s much anticipated Clean Power Plan proposal starts the clock on what will be a multi-year process of review, analysis, planning, and implementation for states, affected sources, and other stakeholders. With an estimated effect of reducing emissions 30% from 2005 levels by 2030, this proposal is akin in scope and potential impact to a national energy plan. However, unlike a national plan, these plan components and implementation will be determined in state capitals rather than in Washington, D.C.

For affected sources, the stakes could not be higher. With no model rule and limited guidance given by EPA, states will have great leeway in determining the appropriate compliance policies. The impacts of the chosen measures will be reflected in power prices, power system reliability, natural gas markets, infrastructure, and in the broader economy. These impacts will be seen in the regulating states and in neighboring states and regional power markets as well. The framework of state-by-state plans could result in a patchwork of requirements for generators and utilities, challenging owners and system operators. The requirements, according to EPA, could lead to a doubling in coal unit retirements and trebling of energy efficiency, accelerating supply and demand trends that are already reshaping the sector. On the other hand, states and affected sources that get their policies right may be well-positioned relative to regional neighbors and competitors, with comparatively lower-cost, more economically efficient, and more business-friendly rules.

Affected sources will have several opportunities to influence this outcome. The first such opportunity comes now, with EPA accepting comments on the proposal until mid-October. In preparation for those comments, sources must understand EPA’s derivation of the state standards and suggest revisions where necessary. Thoughtful comments now may prevent more difficult choices down the road and could reduce compliance costs. Following the comment period, sources must actively engage their states and stakeholders around discussion of plan components and requirements based on integrated analysis of the costs and benefits of potential measures. Those efforts will establish the foundation for the development of the state plans that will start with the release of the final rule by EPA, planned for June 2015. The challenges to utilities will extend beyond that development phase and into the implementation phase should they need to develop and administer new programs, such as those to promote end-use efficiency and distributed generation. Affected sources must provide input at all stages of this multi-year process so that the plans themselves, once finalized and approved by EPA, are achievable and cost-effective.

In this paper, we discuss the critical issues that sources and states face in evaluating EPA’s proposal and developing plans to meet the Clean Power Plan requirements.

Quick Background and Timeline

EPA’s proposed Clean Power Plan would regulate carbon dioxide (CO2) emissions of existing generating units through state-level CO2 emission rate standards. EPA derived the standards by evaluating potential options for emission reductions in each state from generating units and across the broader electric sector. EPA estimates that the rule will reduce total U.S. power sector emissions by 30% from 2005 levels by 2030.

The rule requires that states submit plans for EPA’s review and approval that identify how they will impose and enforce the specified standards. The rule does not specify which measures each state must use, nor does it specify a required level of emission reductions from each type of measure. Instead, each state must determine its optimal plan design and components. This degree of flexibility offers states tremendous opportunity in shaping their plans. However, it also means that states will need to undertake sophisticated analysis to assess the relative costs and benefits of a wide range of options.

According to the timeline proposed in the Clean Power Plan, initial state plans will be due to EPA for review in 2016, with final plans due for states acting alone in 2017 and for states participating in multi-state compliance groups in 2018. However, given the complex process of developing new rules and programs, states, sources, and stakeholders should initiate their efforts now. They will have to continue those efforts through the several stages that will comprise the entire rulemaking process. Those stages will include providing comments on the proposed rule, due in October 2014, through the release and review of the final rule expected in June 2015, and to the development and submission of the plans.

First Order of Business: Understanding the Building Blocks to BSER

EPA is allowing interested parties in the Clean Power Plan rulemaking process 120 days to submit comments to the docket. To make effective comments, affected entities need to understand BSER. The Clean Air Act requires that EPA identify the “best system of emission reduction” (BSER), taking into account the costs and benefits associated with potential reductions in CO2 emission rates. In the Clean Power Plan, EPA did not define BSER as a unit- or facility-specific requirement, nor as a single policy or measure. Instead, it took a broader “beyond the fence” view, identifying four “building blocks” of BSER that incorporate reduction measures both inside and outside the footprint of the affected generators, as shown in Table 1.

For each state, EPA used 2012 generation and CO2 emissions data to calculate the average fossil emission rate for existing units. It then used the building blocks to adjust that rate downward to end up with the emission standard to be met in 2030 for each state.

As an example, we show in Figure 1 how EPA calculated Georgia’s standard. For this example, we have broken the third building block into two components – preserved nuclear generation and renewable generation growth. The nuclear component is an important driver of Georgia’s standard because of the new construction at Plant Vogtle, but the redispatch block played an equally important role. Together, the two blocks combine to account for nearly two-thirds of Georgia’s total required emission rate reduction.

The resulting standard development for each state using the building blocks is summarized in Figure 2. The top of the bar for each state reflects the initial 2012 emission rate while the bottom of the bar shows EPA’s proposed standard. The segments that make up the bars reflect the contributions of each of the building blocks in the calculation of the standard. The figure also shows the wide variation in the standard for each state (from 215 lb/MWh in Washington to 1,783 lb/MWh in North Dakota) and in the required percentage reduction (from 15% in Rhode Island to 84% in Washington).

The building blocks are not requirements by EPA as to how states must meet their standards, so it is not necessary that states and sources achieve each of them individually. However, stakeholders must understand the building blocks and evaluate EPA’s assumptions for each because together they determine the ultimate emission rate standard for each state. These assessments should be the immediate focus of those parties intending to file comments to EPA by October.

Note that the proposed rule also contains an alternative standard (not discussed here) for each state that is less stringent than the proposed standard but that requires earlier compliance. EPA is seeking comments on both approaches.

Beyond Comments: Assessing the Foundations of a Plan

The comment period still represents a relatively small step in the rulemaking process. Beyond that, states and their stakeholders face a number of significant challenges in finding a path forward that will take time beyond the comment period to address.

EPA did not offer a model rule as part of the Clean Power Plan. Instead, it granted a tremendous degree of flexibility to the states to develop the overall design and well as the individual components of their plans. With that flexibility comes the complexity of evaluating potential compliance options and developing the regulations and programs to achieve them.

States, and entities providing input to the states, should begin to evaluate potential pathways in the context of three categories of flexibility: technology, form, and geographic scope. We discuss each of those categories below and note potential areas of focus for the near-term in assessing them.

Flexibility in Technology

Affected sources have the opportunity to advise the states on the technical potential and the impacts engineering solutions may have on competitive position and power markets.

States have the option of choosing multiple pathways to reduce emissions to meet their target standards. The “inside the fence” measures at generating facilities related to heat rate improvements will be an option, in addition to “beyond the fence” renewable and energy efficiency potential. Unit-level fuel switching and co-firing, and even carbon capture, while not called out by EPA, could also qualify. The challenge will be in identifying the viable options. While South Dakota may have tremendous wind resources, for example, states in the southwest may instead have to rely on solar (distributed or central station). Each state will have to evaluate what options are best suited for its generators and make sure that sufficient options qualify under its plan for generators to achieve their reduction potential.

Flexibility in Policy Mechanisms

States and affected entities may reduce compliance costs by understanding the pros and cons of each type of rule and the point(s) of regulation with respect to measuring and achieving compliance.

In the Clean Power Plan, EPA specifies the state targets in the form of emission rate standards (in lb/MWh). This type of approach will require that states perform Evaluation, Management and Verification (EM&V) of efficiency projects, and possibly other reduction measures, so that they can count in the compliance calculation or receive credits for sale into a market-based program. As an alternative, the proposed rule allows a state to translate its rate standard to an emissions mass cap (in tons). The cap will need to be equivalent to the rate standard given projected future demand and generation growth. The mass cap approach will avoid the need for EM&V and crediting because efficiency efforts and non-emitting generation sources will lower absolute emissions, reducing pressure on the cap and contributing to compliance. However, submitting a plan with a mass cap will require that a state perform careful analysis to determine the cap to the satisfaction of EPA. Should the mass cap not correctly account for future demand growth, it may make compliance difficult and more costly. A rate standard, on the other hand, implicitly allows for growth in absolute emissions over time. As a result, a high-growth state such as Louisiana may choose to sacrifice the regulatory benefits of a mass cap in favor of a rate standard that will grant flexibility for growth in emissions.

The state plans will also need to specify where to place the compliance obligation. Plans may assign responsibility to the electric generating units (EGUs), their utility or merchant owners, state agencies, other entities, or a combination. The structure of the power market could impact that decision. States might assign more responsibilities for a broader range of compliance options to vertically integrated utilities in traditionally regulated markets than states with deregulated markets might assign to their independent power producers. At the end of the day however, the state will be ultimately responsible to EPA for meeting its plan’s requirements.

Flexibility in Geographic Scope

Assessing the relative costs of compliance in potential partner states will help affected sources determine whether they will be buyers or sellers in a multi-state program, and how allowance trading or multi-state averaging will impact compliance costs and electricity prices.

EPA’s proposal allows states to join into compliance groups. Collaborating with an existing program, such as the Regional Greenhouse Gas Initiative (RGGI), may ease the rulemaking burden, although even RGGI may require some changes to meet EPA’s requirements. Similarly, California may need to address the first-seller provision, the multi-sector coverage, and other aspects of its cap and trade program before taking on partners. The formation of a new multi-state group, however, might add administrative and regulatory complexity to the development process. For example, member states of the Western Climate Initiative and Midwest Governors Accord started down paths that never came to fruition.

The typical intent for expanding the geographic scope of a program is to improve economic efficiency. That efficiency may come by expanding the number of compliance options at lower cost points. A cap-and-trade or credit trading program would realize that efficiency gain through trading, where an entity with higher compliance costs purchases allowances from an entity with lower compliance costs. However, the number of individual market participants would be an important consideration for states. States with few generation owners, such as Virginia, may think very differently about the potential for trading than states with multiple independent owners, such as Pennsylvania.

Industry Challenges: Implications

All states will face challenges as they determine the optimal components of their plans given their varying reduction requirements, compliance measures, and regulatory requirements. EGUs will likely face enforceable requirements as part of those plans. The compliance burden could range from, at the most extreme, a unit- or facility-level emission rate standard to an obligation to hold allowances to cover emissions under a trading program. Consequently, affected sources will provide important input into the plans so that they are achievable, measurable, and cost-effective. Generation owners and operators must themselves understand the costs and impacts of alternative compliance pathways so that they may provide that guidance.

Power Prices Move Depending on the Approach that States Adopt

The form of regulation, particularly for those programs creating a price on CO2 emissions, will move electricity prices and, therefore, generator revenues. A few potential scenarios include:

The achievement of the standard through a tradable emission rate limit, similar to NRDC’s proposed approach and the way in which EPA modeled the program in its analysis, could result in credits to generation sources that emit below their state standard. Those credits may generate revenue, potentially lowering wholesale power prices through the transfer of payments from high emitting sources such as coal generation, to low emitting sources such as gas generation, so long as such gas generators continue to be the marginal units that set power prices.

Under a portfolio approach that requires an amount of renewable generation through an RPS, an amount of energy efficiency through an efficiency standard, and generator emission reductions at the source, wholesale electricity prices could be little affected. Instead, the costs of the program would be primarily felt through retail rates.

A plan with a mass-based cap with trading would add a positive dispatch cost to all emitting units, and all else equal, result in higher wholesale and retail power prices.

Generators in states that opt to join multi-state groups may benefit from lower cost compliance options in the partner states, or from generating emission reduction credits for sale in those states.

Multi-state Management Requires Attention

Planning efforts will be particularly challenging for organizations that own or manage generation sources in multiple states. Since each state could potentially develop a different plan, companies could find themselves keeping up with a host of idiosyncratic policies across their fleet. For example, companies may find themselves managing a CO2 allowance book in one state and administering an energy efficiency program in another state without the opportunity to gain synergies across those operations. Similarly, regional RTOs, and particularly those with centralized dispatch models such as PJM and MISO, will need to understand the implications that a potential patchwork of regulatory regimes would have on the cost of dispatch for generation units and the flow of power between states. A state such as Illinois that falls into more than one RTO footprint will need to understand the impact of its plan in the context of both RTOs.

No matter what pathway a particular state chooses, its regulations will not be the sole determinant of impacts on its generating sources. The regulatory approaches in neighboring states could create inconsistent market signals at the borders, or along the seams of state and regional programs, that are equally important in driving market outcomes. For example, neighboring states with different CO2 price signals resulting from their respective programs could see shifts in transmission flows and resulting changes in relative electricity prices. Similarly, a state that offers incentives to boost renewable development may draw projects away from other nearby states, impacting both the generation mix and economic development in both states.

Infrastructure Needs Shift

The Clean Power Plan may shift demands and stresses on energy infrastructure. For instance:

In its analysis, EPA projected coal unit retirements to double by 2030 relative to a business-as-usual case. While the actual result may differ, generators and system operators must examine the retirements that might result and how they could impact system reliability, as well as capacity market dynamics in relevant areas.

Generators will also need to know whether they have access to adequate gas pipeline infrastructure, and the delivered cost of the fuel, should they need to rely on gas-fired generation to a greater degree than in past years.

Similarly, companies seeking to deploy more wind will need to examine whether or not there is adequate transmission capacity to support development. States seeking to deploy more distributed generation (DG)—such as solar PV, and CHP—will need to understand the impacts of high DG penetration on the distribution grid, and how energy storage fits into this plan.

Energy Demand Responds

State plans will affect the broader energy industry as well through their impacts on fuel use and electricity prices. Stakeholders in these markets — natural gas suppliers, coal suppliers, pipeline owners, etc. — need to be engaged from the comment period through the plan development. The resulting energy price changes will flow into broader economic impacts as well, including job growth and economic activity, with the potential to strengthen certain industries and weaken others. These factors will flow back into electricity demand, potentially forcing utilities to reconsider their emissions compliance decisions and broader capacity strategies so as to avoid stranded control investments at coal facilities and the high cost of non-compliance.

Industry Challenges: Implementation

Utilities may face implications beyond the costs of reducing or paying to cover their emissions of CO2. They – and other retail electricity providers – may also be burdened with implementing portions of the state plans themselves.

Utilities could see new roles emerging for themselves as operators of new or expanded programs. For instance, a state plan could require its utilities to develop new end-use efficiency and distributed generation incentive and potentially deployment programs. Accomplishing that task would require analysis of the potential resource for both, locational impacts, development of a plan to reach and encourage adoption, outreach to participants, measurement and verification of uptake, and program administration. Similarly, states that impose policies such as renewable portfolio standards might require that load serving entities acquire, verify, and track qualifying generation to meet those requirements. Utilities would also need to consider the technical impacts of such distributed energy resources on their distribution grid.

In states where the plans expand these types of programs, those affected may have higher implementation costs and face greater program complexity. For many utilities and states, however, it will be their first time developing such complex programs with CO2 emission reduction goals in mind. In that regard, utilities must determine the forms of program that impose the least administrative burden and inform their states accordingly.

Putting it all Together

There is a high likelihood of a transition towards a power market where there is a penalty for CO2 emissions—whatever form that policy might take. Given that reality, utilities and generators would be prudent to account for a carbon price in their strategy and planning, and to determine what form of enforcement and regulation scheme would work best for them.

While the proposed Clean Power Plan offers a host of flexibility measures, EPA did not provide a model rule, leaving states to analyze the costs and benefits of each option available to them and devise their own plans. These plans will drive markets in their own state and in neighboring states and broader regional power markets. Consequently, any analysis of a potential state plan must consider state-level and regional impacts. The process of choosing a state plan will be particularly challenging since the compliance to the proposed standard needs to be demonstrated at the state level, even though the impacts of a state plan will likely cross state boundaries.

ICF provides the type of integrated analysis that will be required to assess the multitude of options available to states in their planning efforts. We continue to analyze all facets of the proposed rule to understand the relative contributions of the building block components to state compliance options, as well as the impacts of the rule on individual generating assets and wholesale power markets. We note that such analyses will be particularly important in assessing how state plans affect power markets, fuel markets, as well as in designing and implementing energy efficiency, and distributed generation measures through different forms of regulation.

About the Authors

Chris MacCracken is a Principal with ICF International’s Energy Advisory Services team. He directs studies examining the impacts of environmental regulation on emission, power and fuel markets, compliance planning, and generating unit valuations. Chris’ clients include electric utilities, IPPs, industry associations and non-profit policy organizations. He is currently leading projects related to the development of CO2 standards for existing sources. He is also the lead author of the Regulatory chapter in ICF’s quarterly ICForecast publication.

Steven Fine is a Vice President with ICF”s Energy Advisory Services practice. At ICF, his work has concentrated on evaluating the economics of conventional and renewable energy resources within the context of developing environmental and energy regulations. He works with many of the major US power companies and developers in assessing the impact of environmental regulatory policies, and renewable portfolio standards on unit and fleet compliance, environmental capex, asset valuation, and asset deployment and retirements. Steve has led ICF’s support of numerous multi-stakeholder engagements including EEI’s Regulatory Pathways Analysis, ICF’s AB32 Cap and Trade Study, AWEA’s National Wind Study, as well as the electric sector analysis for US Climate Action Partnership (USCAP). Steve was an invited panelist to a Senate Roundtable discussion on the future of federal air regulatory legislation, and is currently working with a number of stakeholders to evaluate the impact of potential NSPS policy design at the federal and state level.

Philip Mihlmester serves as Executive Vice President, Global Energy, at ICF International. In this capacity, he oversees the firm’s global energy practice coordinating the efforts of over 1,300 energy professionals worldwide in the areas of electric power, petroleum, natural gas/LNG, coal, climate change, emissions, energy efficiency/demand side management, environmental and water issues. He advises senior corporate and government managers on a variety of strategic issues in the energy sector, including transmission, asset optimization, energy efficiency, and climate issues, as well as infrastructure security. Mr. Mihlmester has led project teams in support of major Government energy efficiency programs, including EPA Energy Star and the Department of Energy’s Buildings Energy Challenge programs. He has also advised major electric and natural gas utilities on the design, implementation, and evaluation of energy efficiency program portfolios. Mr. Mihlmester holds an M.S. in Operations Research from the George Washington University in Washington, D.C., and earned his A.B. at Columbia University in New York, NY.

David Pickles has 15 years of experience as a senior executive and utility-industry consultant on energy efficiency and new businesses opportunities. He heads the Southern Region of the Energy Policy and Programs Practice and is responsible for all regional activities, including project execution, business development, and management. He has worked on numerous market potential studies and is experienced with energy program design and management, product assessment and business planning, marketing, operations, mergers and acquisitions, strategy, and turnarounds. He has developed profitable new ventures for enterprises ranging in value from $1 million to $12 billion. He has an M.S. degree in Regulatory Economics from Wyoming University where he also earned a B.S. in Economics.

About ICF International

Since 1969, ICF International (NASDAQ:ICFI) has been serving government at all levels, major corporations, and multilateral institutions. With more than 60 offices and more than 4,500 employees worldwide, we bring deep domain expertise, problem- solving capabilities, and a results-driven approach to deliver strategic value across the lifecycle of client programs.

At ICF, we partner with clients to conceive and implement solutions and services that protect and improve the quality of life, providing lasting answers to society’s most challenging management, technology, and policy issues. As a company and individually, we live this mission, as evidenced by our commitment to sustainability and carbon neutrality, contribution to the global community, and dedication to employee growth.

Any views or opinions expressed in this paper are solely those of the author(s) and do not necessarily represent those of ICF International. This White Paper is provided for informational purposes only and the contents are subject to change without notice. No contractual obligations are formed directly or indirectly by this document. ICF MAKES NO WARRANTIES, EXPRESS, IMPLIED, OR STATUTORY, AS TO THE INFORMATION IN THIS DOCUMENT.

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Comments (5)

That is such a messy site that I can find nothing in the oil drum but oil Ormond.
Can you provide a link to you man?
Bill

Posted by Steve Campbell on 03/20/10, 01:49 PM

Long blades necessitate strong materials for the varied winds. Efficient blades help gather the lesser energy available for the most time many places. Some of us want to get all the bang for the buck we can. Perhaps as more people get interested in harvesting energy good standard practice will dictate doing energy intensive tasks when the energy is readily available.
From another practical standpoint why take materials that make 10 efficient machines to only make 6 inefficient machines? It also stands to reason that some of the wasted energy is being transmitted into sound as a waste product with less efficient blades.

Posted by Lewis Dickens on 02/26/10, 04:36 PM

Toomas, I can't make sense out of your comment.
Efficiency is an extremely important concept in Engineering. That the solar panels on the U of M car in the Australian Solar race were less efficient than the first and second place cars is the reason that they took third place. It's all about efficiencies.
Ormond, I looked at that site and could not find where efficiencies are discussed. The 3 bladed fans are of low efficiencies, have been for years.
Perhaps the most irritating fact is that the manufacturers do not post their efficiencies. It's a complete nonsequitur. There should be national dynamometer test standards and procedures so that comparisons can accurately be made.
Bill pointed out that these were NOT propellers which are designed to place power into the wind... propell. His designs are resistors designed to extract energy from the wind. The three bladed fans actually are wing foils designed to sail in the wind. There are three distinctly different designs for dealing with the wind.
If you can get Jerome to opine on efficiencies, that would be great. That they are never discussed is disturbing to me.
Bill did develop designs for arrays of 50' diameter fans. He was sure that an 18' diameter could easily provide all the power requirements for any normal home.

Posted by Toomas Pungas on 02/04/10, 11:59 PM

What matter with wind turbine efficiency? You need more power from same wind? So make blades longer. How much the gallon of wind? :)

Posted by Ormond Otvos on 02/04/10, 02:42 PM

Points well taken, but one gets the impression that not much effort was made to inquire about efficiencies from the makers of wind turbines.
Jerome a Paris from theoildrum.com is the man to ask.

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